The decision to limit mercury provides cover for utilities reluctant to spend on controlling NOx and SO2, while boosting other companies
PoolCo and Market Dominance
monopoly regulation. Utility mergers could increase the market dominance of the remaining players and lead to windfall profits under a PoolCo arrangement. t
Randall Falkenberg, vice president of J. Kennedy and Associates, Inc., has a BS and an MS in physics and 17 years' experience in the utility industry. He has appeared as an expert witness in more than 70 utility industry hearings, and written numerous studies examining the economics of power generation and cogeneration projects on behalf of regulators, financial institutions, and industrial power and steam consumers.A Computer SimulationTo simulate a hypothetical New York PoolCo, we examined data from each IOU in the state: load and capacity, plant capacities, capital costs, fuel and O&M expenses, and estimates of outage rates. We also collected comparable information for NUGs and offsystem purchases. As in the California PoolCo model, we assumed that NUG generation was directly assigned. We based all data on 1993 values, as reported in each company's FERC Form 1 filing. Given the limited level of detail, we offer our results primarily for qualitative comparison and for drawing inferences.
Our model reflected conventional production cost simulation. Dispatch of power resources was done on a poolwide basis, and the dispatch priorities were based on bid prices rather than incremental cost. Generation is allocated to power plants based on economic dispatch, probabilistic treatment of full and partial forced outages, maintainance requirements, and any applicable must-run constraints.
Once the dispatch sequence is determined, the overall system pricing is determined. For submarginal (i.e., baseload) units, the average "award price" is simply the probability weighted average (PWA) system incremental bid price of the "marginal" (or cycling) units across all hours in the time period modeled. (This period may be as short as one hour or as long as one year.) For units at the margin, the award price is the PWA of the unit's own bid price for hours when it is the "swing unit," and the PWA of the higher-bid-price units dispatched after it is fully loaded.
For example, if Unit A is the most expensive (highest bid price) unit on the system, its award price, AP(A) is equal to its bid price P(A). This bid price is in effect during the hours of the period when Unit A is dispatched, H(A). If Unit B is the second highest bid price unit, with price P(B), and operated for H(B) hours, then for Unit B the award price is set by Equation 1:Equation No. 1
Award Price for Unit B =
AP(B) = [(H(A) x P(A) + (H(B) - H(A) x P(B)] / H(B)A similar equation is applied for each of the marginal or swing units on the system. Revenues derived from each unit represent simply the product of the award price, AP, and the unit generation, as determined by the production-cost dispatch model.
The model also estimates the stranded cost (SC) for each unit as the difference between the revenues produced by the unit and its conventional revenue requirement, RR, as allowed under current regulatory practices. Typically this result would include fuel, variable and fixed (O&M),